Viscous fluids are used in a variety of operations and treatments in oil and gas wells. Such operations and treatments include forming gravel packs in well bores, fracturing producing zones, performing permeability control treatments and the like. Hydrocarbon producing wells are often stimulated by hydraulic fracturing treatments. In hydraulic fracturing, a viscous fracturing fluid is pumped into a subterranean formation at a rate and pressure such that one or more fractures are formed or enhanced in the formation. After the fractures are formed or enhanced, the fluid viscosity is reduced and the fluid is removed from the formation. In some cases, the fracturing fluid also functions as a carrier fluid, carrying proppant particles, e.g. graded sand, into the fractures. The proppant particles are suspended in the fracturing fluid and are deposited in the fractures when the fracturing fluid viscosity is reduced. More viscous fracturing fluids can more effectively form or extend fractures and carry proppant particles.
Fracturing fluids typically are made viscous by use of polymeric materials. Generally, the more polymer that is used, the more viscous the fluid will become. For example, polymers such as cellulose, guar, and their derivatives have been used to form aqueous gel treating fluids having viscosities on the order of 1000's of centipoise. Gels made with linear polymers sometimes have sufficient viscosity to create fractures in some rock formations. For other formations, however, more viscous gels and/or gels with more internal structure are desirable. The polymeric material may be crosslinked to increase viscosity and build internal structure. The internal structure created by crosslinking is important because for at least some formations the fluid must be able to carry proppant, e.g. sand particles, into the fractures. Without internal structure proppant may settle out of the fluid even if the fluid is very viscous.
Fracturing fluids often include breakers for reducing the viscosity of the fluid after the fluid has effected fractures and/or positioned proppant particles. Breakers degrade polymers in the treating fluid, thus breaking the gel and reducing the fluid's viscosity. Breaking the gel converts the viscous fluid into a more free flowing fluid, which can be removed from the formation more easily than a viscous fluid. The thinned fluid also allows oil and/or natural gas to more freely flow out of the formation. Thinning the fluid also reduces the likelihood that the polymer will contribute to an oil/water emulsion. Unbroken polymer can stabilize emulsions of oil and water, which causes problems when the oil is extracted. The thinned fluid also leaves proppant particles in fractures where they function to prevent the fractures from closing and help to form conductive channels through which hydrocarbons and/or natural gas readily can flow.
Known breakers may be liquids or solids, and include, but are not limited to, chemical oxidizers, enzymes, and acids. Breakers are formulated to remain inactive while the treating fluid is introduced to the subterranean formation and until a reduction in viscosity is desired. The breaker may be formulated to be “activated” by certain conditions in the fluid (e.g., pH, temperature, etc.) and/or by interaction with some other substance. Alternatively, the breaker may be encapsulated with a coating that delays release of the breaker. Typically liquid breakers are activated by temperature or time delay. Another method of controlling breaker activity is by loading concentration of the breaker.
Treating fluids generally are water based. Materials soluble in water can be used as breakers if their solubility profile is such that they dissolve and thereby become active to break the gel at the time when a reduction in viscosity is desired and not before that time. If a material dissolves too slowly, it could not be used as a breaker. If a material in its native state dissolves too quickly it sometimes can be coated to delay its dissolution and thereby delay the reduction in viscosity until the appropriate time.
Known methods of controlling breaker activity have limitations. For example, coating is not a viable option for some materials, such as sodium persulfate, because the coated material has particle sizes that are not uniform. Moreover, encapsulated products often do not have a uniform distribution of coating, which leads to inconsistent break profiles. Decreasing the loading concentration of the breaker to delay breaker activity could lead to insufficient concentrations to fully break the treating liquid.
It would be advantageous to provide breakers soluble in a treating fluid, where the breakers have solubility profiles suitable for breaking the viscosity of a treating fluid only at the desired time, and where the breakers do not require a coating.